A variety of techniques have been used to enhance the recovery of hydrocarbons from subterranean formations in which the hydrocarbons no longer flow by natural forces. Such techniques can include water injection and/or subsequent miscible carbon dioxide flooding, among others. Water injection can be useful to recover some hydrocarbons, however, only about a third of the hydrocarbons are recovered using this technique. As such, typically water injection procedures are followed by an enhanced oil recovery technique such as miscible gas flooding. Miscible gas flooding can be performed with a carbon dioxide, to reduce the viscosity of the crude oil present in the subterranean formation in order to increase the flow of hydrocarbons to a production well. Carbon dioxide, which acts as a solvent to reduce the viscosity of the crude oil, is one of the most effective, and least expensive, miscible gases. During the miscible carbon dioxide flooding procedure the carbon dioxide is typically in the liquid and/or supercritical phase.
Miscible carbon dioxide flooding, however, can be accompanied with a number of drawbacks. One main problem encountered is poor sweep of the subterranean formation. Poor sweep occurs when the gas injected into the reservoir during a miscible carbon dioxide flooding process flows through the paths of least resistance due to the low viscosity of the gas, thus bypassing significant portions of the formation. When the gas bypasses significant portions of the formation, less crude oil is contacted with the gas, reducing the likelihood that the gas will reduce the viscosity of the crude oil. Thus, the gas injected during the miscible carbon dioxide flooding process is meant to “sweep” the crude oil toward the production well by lowering the viscosity of the crude oil. However, when the gas does not contact a large portion of the crude oil contained in the subterranean formation, a large portion of the crude oil in the subterranean formation is left behind, producing poor sweep. In addition, due to the low density of the gas, the injected gas can rise to the top of the formation and “override” portions of the formation, leading to early breakthrough of the gas at the production well, leaving less gas within the subterranean formation to contact with the crude oil, again reducing the likelihood that the gas will reduce the viscosity of the crude oil.
To enhance the effectiveness of the miscible carbon dioxide flooding process it has been suggested that a foaming agent or a surfactant be included in the process to help to generate a foam in the formation. A foam can generate an apparent viscosity of 100 to 1,000 times that of the injected gas, therefore, the foam can inhibit the flow of the gas into that portion of the subterranean formation that has previously been swept. In other words, the foam can serve to block the volumes of the subterranean formation through which the gas can short-cut, thereby reducing its tendency to channel through highly permeable fissures, cracks, or strata, and directing it toward previously unswept portions of the subterranean formation. As such, the foam can force the gas to drive the recoverable hydrocarbons from the less depleted portions of the reservoir toward the production well.
The surfactants used in creating foams for miscible carbon dioxide flooding processes, however, have suffered from a number of drawbacks. For example, traditional surfactants, such as ethoxy-sulfates, can create emulsions of oil and water which are difficult to break. The emulsions can cause permanent damage to the formation by irreversibly plugging pore throats. Further, these emulsions when produced may be difficult to separate or “break” and may necessitate costly solutions to remedy. Another problem encountered by prior art surfactants has been the selection of anionic surfactants that have a high affinity to formation rock within the reservoir, for example, carbonate. Surfactants with a high affinity to formation rock can adsorb into the formation rock, leading to surfactant loss. Without the surfactant present, there is less likelihood of forming foam within the reservoir, also leading to early breakthrough and poor sweep, as discussed herein.